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Chinese New Year sees no-monkeying-around stance on steel overcapacity

As China takes off for the new Year of the Monkey, the mood for many in its steel industry will decidedly be sombre, judging from the recent slew of warnings several steelmakers have issued, predicting massive losses for 2015.

Over the week-long break, the industry will take time to digest the bitter medicine that the State Council has said would follow, after its announcement yesterday of guidelines to not just eliminate 100-150 million mt of capacity over the next five years, but to manage the resulting fallout from unemployment.

Skeptics may dismiss the news as a familiar refrain they’ve heard one too many times with limited outcomes, but many signs point towards a resolve by the state that is unwavering.

For one, the latest pledges to tackle the problem have been reiterated by the highest levels of the Xi-Li administration – the president and premier themselves – unlike earlier pronouncements, which were issued mainly by ministerial-level organs.

Furthermore, there is now recognition that excess capacity can’t just be wished away without a plan to address the ill-effects of massive job losses. Plans to provide resettlement, retraining and financial compensation to displaced workers and to support companies and local governments that are willing to bite the bullet seem to be a step in the right direction.

In its statement, the government was forthcoming in noting that staggering losses by steelmakers over an extended period have forced the sanguine look into the mirror at the underlying problems of rapid over-investment in the sector.

Out of the country’s ten biggest steelmakers by output that are listed and have issued earnings forecasts, only three expect to turn a profit, while six have flagged staggering losses running into the billions of yuan.

Dirt devil: Airlines filter through info on latest fuel quality issue

At the Platts Middle Distillates Conference in Antwerp, Belgium, in late January, those attending spoke a diesel-focused language, this being Europe where people mostly drive diesel cars even after the VW scandal.

So I had to filter out a lot of information to get any dirt on jet fuel — also a middle distillate. And what did they talk about for jet fuel? Not prices or inventories. But filters. And dirt.

Panelist Mike Farmery can make aviation fuel quality sound entertaining. A longtime global fuel technical manager for Shell Aviation who now runs the consultancy Clear and Bright, he described trends in jet fuel quality to the nearly 100 people at the conference.

He touched on the nearly ended spec battle to allow FAME (fatty acids methyl esters — think Crisco in an engine instead of a fryer) for greater pipeline movement as a biofuel, which jet engine makers have opposed for years. Water contamination and thermal stability issues came up. But those areas have trended for a while in airline circles, where it’s certainly a more serious issue if your fuel fails to perform at 30,000 feet above ground in a plane rather than inches off the ground in a car.

But Farmery noted that more trading and shipping of jet fuel worldwide has meant more time on potentially older, rusty ships. Many refineries around the world have closed and converted into storage terminals in recent years, while new megarefineries in the Far East and Middle East have emerged along with expanded refineries in the US. This trend has increased the shipping of jet fuel and has made managing dirt contamination more challenging.

It’s not hard to get rid of dirt, mind you. But you have to be more diligent, as anybody who’s ever camped in the desert or the beach knows. It’s more time-consuming to put in more or better filters and change them more often. It’s also more costly.

He outlined several cases of problems detected at import terminals, including one European terminal where it took 10 days to process fuel and $150,000 cost in filters that needed to be changed every eight hours.

Farmery also noted that ships are required to come to port with their cargo inert (non-explosive). That usually meaning using carbon dioxide exhaust gas from the engines. Cheap and easy, but it causes more soot and sulfuric acids to get into the jet fuel than normal.

There are tight checks to control particle sizes in fuel coming out of the refinery, and aircraft are ultimately protected by ultra-fine filters on fueling equipment. But fewer checks or just self-assessment checks exist in the middle of the supply chain, so it could be easily overlooked.

Such particulate contamination has risen high on the agenda for jet fuel forums, as experts look at the number and size of particles in the specifications. “The spec just isn’t very good at qualifying what is dirt,” Farmery said.

Import terminals may be the best place to catch the problem, through on-site filtration to deal with problem cargoes. But easier test methods would help, along with contamination limits along many points of the supply chain.

“We can fix it, but it’s about allocating costs and filtration,” he said. “Thirty-five thousand feet is no place to change filters.”

Source: http://blogs.platts.com/

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Will the US’ ‘M’ gasoline be dead like the mummy? Some say yes

Me: “Let’s talk about prices at the pup.”
My many critics: “Don’t you really mean prices at the ‘pump,’ doofus?”
No, in this case I really do mean prices at the pup. Why? No “M.”
Why so glum, chum? Maybe because unfinished gasoline is nudging finished gasoline out of the dog bed that is oil. (Photo by Sara Butler)
Why so glum, chum? Maybe because unfinished gasoline is nudging finished gasoline out of the dog bed that is oil. (Photo by Sara Butler)
The venerable M-grade, a benchmark in the gasoline trade for decades, soon would lose some of its influence under a change proposed by the nation’s largest pipeline, Alpharetta, Georgia-based Colonial. The company, citing feedback from users in Houston last week (February 1), intends to drop M-grade gasoline from its shipping schedule.
It’s said around the Platts office that J.P. Morgan — the person, not the bank — used to trade M-grade gasoline when he wasn’t giving shiny dimes to tots. It influences the price of gasoline going to Mexico. It influences the price of naphtha going to South Korea. It probably influences the price of Flamin’ Hot Cheetos at your local Chevron gas station.
According to a story by Platts’ Amanda Rayborn, much less M-grade has been shipped on the pipeline system compared with the last few decades. Colonial, the nation’s largest and busiest pipeline, links the Houston area to North Carolina via gasoline-only 1.37 million b/d Line 1, and then to New Jersey via 885,000 b/d refined products Line 2.
What’s the beef with M? (Source: Nero-Film)
What’s the beef with M? (Source: Nero-Film)
The pipeline used to have more “M” than the word “mummydom.” These days there’s no timeline for dropping M-grade, a product that has seen a considerable decline in shipping volume, according to Colonial officials.
These are, indeed, tumultuous times for the 87-octane M-grade gasoline. Colonial earlier announced plans to drop M-grade at 7.8 RVP from the shipping schedule, meaning the cash markets will shift focus to the more widely traded 9 RVP gasoline this summer. The 7.8-RVP M-grade was the basis for multiple futures contracts, so that sector of the market will have to alter its trading profile starting soon.
There are signals the grade still matters. Market talk points to considerable blending of M-grade into RBOB blendstock once it reaches the northernmost point of Line 3 at Linden, New Jersey. That’s right — finished gasoline is turned back into blendstock. It’s like turning cupcakes back into flour, but it works in the energy markets.
It’s hard to get a handle on how much M-grade is shipped on Colonial, with that data regarded as proprietary. A good rule of thumb is that there are at least three barrels of CBOB blendstock in the cash gasoline market for every barrel of M-grade gasoline.
And don’t get me started on V-grade. Colonial told shippers late last Friday that V-grade at the lowest-traded RVP, 7.8, might be dropped from the summer shipping schedule. Its fate is being decided separately from M-grade.
For now, it is still relevant. With the “V.”

Source: http://blogs.platts.com/

US scrap industry returns to an event where many were queasy last year

An annual scrap industry event in St. Louis every February has grown in mass and scale over the past decades. Once a regional chapter dinner, it is now a full-scale party that attracts scrap dealers and mill buyers from across the country.

ISRI’s Mid-American Consumers Night banquet on Tuesday evening is the main event, but meetings begin as early as breakfast on Monday. Industry friends begin gathering in the Union Station Hotel lobby well before the start of the banquet, and this year’s event brings back memories of last year, when scrap suppliers were reeling from a February price crash that finalized just days earlier.

The annual open-bar themed banquet rages all night with drinks, food, entertainment, drinks, music, and more drinks. Needless to say some attendees head for the airport Wednesday morning bleary eyed.

At last year’s 68th annual Consumers Night, scrap dealers showed up to the event bleary eyed, having landed in St. Louis looking like they had just seen a ghost. What they had really seen was a $100/lt price plunge, the likes of which had not been experienced this decade.

There was shock, disbelief, and a certain numbness among the dealer base at the event.

Looking back at my coverage a year ago, the first sign of the February price crash were evident in a story published Jan. 19. The headline read “Weak fundamentals undercut US scrap prices.” After raising prices around $20-$30/lt during the January buy week, mill buyers cell phones rang off the hooks, their inboxes were flooded with emails from dealers and they quickly pulled back.

Mills eventually bought at sideways and then shut their doors. Scrap was left unsold and it began to overhang the market, setting the stage for what would soon become the ‘F-word’ for a dealer base — as in “February 2015.”

A year has passed since that fateful February buy week and pricing still has not recovered, but this year’s Annual Consumers Night will have a different feel to it.

Pricing is actually lower now ($190-$200/lt delivered mill for shred in the Midwest) than it was last year post-‘F-word’ ($245-$260/lt). But the supply-side has done a better job of adjusting to this new norm. There is no China to bail us out this time, like there was in the 2008 crash — just hard work and rationalization.

There have been idlings, adjustments, restructuring and, unfortunately, shutdowns and bankruptcies, but for those left standing in this market and on hand in St. Louis this week, there will be a reason to raise a glass and make a toast to surviving.

February 2015 set off a chain reaction in the market, and survival of the fittest is the basis of evolution and efficiency. While 2016 is still young, Tuesday night will be a good chance to assess how things may look for the year. Cheers!

Source: http://blogs.platts.com/

Are oil market uncertainties, falling prices taking the sparkle out of London IP Week?

You know that London IP Week is underway when hundreds of attendees gather at the May Fair Hotel to attend the Platts London Oil Forum, which was Monday. Attendance was so high that the 500-plus participants filled three large conference rooms, linked by live video feed and connected by iPads, which got them sharing their views during a series of crucial updates and panel discussions.

Speculation about the price of a barrel of oil has made its way from the business sections to the front page, and as we fast approach $30/b, the hot topic for presenters and participants at LOF 2016 was: How low can it go?

A live poll on the day showed that there wasn’t consensus amongst attendees, with 30% believing that front-month ICE Brent futures contract will be trading at $35-$45/b this time next year, and 40% believing the price will rise to $45-$55/b. What’s significant is that 21% of those who voted believed that price will fall further, with 7% believing it could drop to as low as $15/b.

What is clear is that the drop in price is having an effect on the industry, and this was evident at London IP Week. Joel Hanley, Platts editorial director for European and African oil, summed it up nicely when he said that there are fewer IP Week parties this year, and the drinks being served have also taken a hit. When Platts hosted LOF 2014, a barrel of oil cost roughly the same price as a bottle of Bollinger La Grande Année Brut 2005, whereas now a barrel of oil is comparable to a bottle of supermarket own label Champagne (Tesco Finest Vintage was mentioned).

If the price continues to drop, Hanley questioned whether it will be comparable to cheaper supermarket Champagne or even as low as a bottle of cheap prosecco — there will still be fizz, but if the supply glut continues, will the sparkle be lost for the foreseeable future?

This supply glut was a key feature of the debate. Hanley reported that OECD countries currently hold 3 billion barrels of oil in stock, an all-time high. Given the close correlation between oversupply and the falling oil price, this issue needs to be addressed, but when polled, 76% of respondents at LOF 2016 did not believe that OPEC would agree to cut it production in 2016.

Weighing up issues which may have an impact on supply and demand in 2016, attendees were also polled on US and Iranian exports and Chinese demand. With the historic lifting of the 40-year-old ban on exports, 53% of respondents believed US crude exports would be sporadic and involve a range of grades in 2016.

Asked about the impact that lifting sanctions would have on Iranian exports, a significant 77% of respondents didn’t think that Iran would be able to regain its pre-sanctions European market share.

And when questioned about Chinese demand, there was less consensus, with 46% of believing that China’s crude imports were likely to grow by up to 3%, and 43% believing this growth could reach 7%.

Platts has reacted quickly to significant industry change and Jonty Rushforth, Platts director of oil and shipping price group, used LOF 2016 to announce the launch of a new Dated Brent Cost-Insurance-Freight (CIF) Rotterdam assessment, as well as discuss new assessments designed to bring transparency to the US Gulf Coast crude and condensate export market.

When polled specifically about the impact of US exports on European refiners, attendees had a range of views. Some 30% of respondents thought any impact wouldn’t be felt until 2017/2018, while 26% believed the impact won’t be felt until after 2018 and 40% thought that US exports won’t have an impact on European refiners at all.

It looks as though 2016 is set to be another year of significant change. From the buzz at LOF 2016, however, it’s clear that business continues.

Source: http://blogs.platts.com/

The US enters a brave new world as it begins LNG exports

Next month, the US is set to export its first cargo of LNG from the continental US. Cheniere Energy, the company that won the highly-contentious race to be the first exporter out of the gate, will have some advantages over its US peers, but the global LNG landscape has changed significantly since the company first proposed to build its LNG export terminal over a half-decade ago.
Before diving into the current state of the world LNG market, let’s take a step back and see how we got to where we are today.
The beginning
In 2001, Cheniere Energy made an announcement to build four LNG import terminals in Louisiana, at a cost of $1.2 billion. As Charif Souki, Cheniere’s CEO at the time, hit the road to raise money, he told investors a simple message: The US is addicted to natural gas and we are running out of it. Therefore, we must import natural gas via LNG from abroad. After seven years, Souki and Cheniere’s vision became a reality, with the inauguration the Sabine Pass LNG import facility in April 2008.
But between 2001 and 2008, the forecast for US natural gas went from gas shortages to gas gluts. Showing off a sparkling new, state of the art LNG import facility, Cheniere was literally trying to sell natural gas into a sufficiently supplied market. It was like trying to sell ice in the North Pole or chocolate to someone in Hershey, Pennsylvania.
Cheniere then set out to do the complete opposite of what the planned to do a decade ago: export LNG. In September 2010, Cheniere was the first company to apply with the US Department of Energy for a permit to export LNG.
The art of a deal
By late 2011, Souki managed to work out a deal for Cheniere to sell $8 billion of LNG over 20 years to BG Group, which is now owned by Shell. In a nutshell, Souki’s pitch was this: US natural gas prices are forecast to stay low because of the abundance of newly-accessible shale gas resources, while natural gas and LNG prices are expected to remain high in Asia.
Why was Cheniere so confident that LNG prices were going to stay high in Asia? At the time, nearly all LNG prices in Asia were linked to oil.
This value proposition was successful, as Cheniere has been able to sell 80% of their LNG export capacity at Sabine Pass under take-or-pay contracts.
The sober start to 2016
Fast-forward to 2016. Cheniere is expected to export its first cargo of LNG out of Sabine Pass this March. As Cheniere, along with other hopeful LNG exporters, know all too well, market dynamics never stay constant and volatility is the name of the game. Commodities are cyclical. When Cheniere and other companies decided to build multi-billion dollar LNG export terminals, there was a large price difference between gas prices in the US and Asia.
pedersen-jkm-lngFor example, the average price for a spot cargo of gas in Asia in 2011, using the Japan-Korea Marker, JKM, was $14.02/MMBtu. A key reason prices spiked was the Fukushima nuclear disaster, which occurred in March 2011, leading Japan to shut 47.5 GW of nuclear generation capacity.
As new LNG facilities came online, prices have faced downward pressure. In 2015, the average JKM price was $7.45/MMBtu, and as of Feb. 3, the average price this year has been $5.73/MMBtu.
Awash in LNG
So how did we get to where we are today? Put simply, demand has recently failed to keep up with supply. Platts unit Eclipse Energy Group data shows global gas demand growth was insignificant in 2015, rising by a mere 700 MMcf/d, while at the same time roughly 2.2 Bcf/d of new export capacity was added. Over the next five years, total global export capacity is expected to grow by an exceptional 133.5 mtpa (17.8 Bcf/d), a 44% increase.
The US as a global swing supplier
Eclipse data shows that by 2020 the US will have become home to 15% of global liquefaction capacity and could become the world’s third largest exporter (behind Australia and Qatar). And due to the inherent flexibility of US LNG tolling agreements, American exporters have a good chance of becoming a swing supplier. Unlike other LNG contracts, US LNG tolling agreements do not have fixed destination clauses, allowing US-sourced LNG cargoes to show greater optionality in spot markets.
pedersen-gas-prices-forecast
The balance between global LNG demand growth and global LNG supply will be the two key variables in determining how quickly and to what extent American LNG plays a role in the global market of the future. Another key factor will be the price of US natural gas. Platts Analytics forecasts Henry Hub spot prices averaging $2.45/MMBtu in 2016 and increasing to $4.19/MMBtu in 2020.
Even though it appears to be a buyer’s market for now, the US is quickly becoming ready for when the tide turns. At this point, the world will find out just how capable the US can be in the LNG market. For now though, at least they can say something that they weren’t able to say a year ago: We are ready to play.

Source: http://blogs.platts.com/

SoCal Gas’ Aliso Canyon gas storage leak raises questions about California markets

The Southern California Gas Company is one of the biggest local distribution companies in the United States, covering much of Southern California, and is a regulated utility within Sempra Energy. One of the wells at its Aliso Canyon storage site has been leaking gas for over three months now, and it’s not expected to be stopped for another month.
We’re not here to comment on the politics or social impact of this event, but we are tracking how this is impacting the California natural gas market. This has really shaken up expectations for the California gas market, as the future of the facility after the leak is repaired is unknown. So why is Aliso Canyon such an important storage facility?
Aliso Canyon is the fourth-largest storage facility in the country, and its 86 Bcf of working gas capacity makes up 64% of SoCal’s total storage capacity. SoCal usually doesn’t even pull inventories down to 49 Bcf, which is the total capacity of SoCal’s other three storage fields. 01-28-16 SoCal gas storageSoCal will not be able to inject into the field until the utility can prove to regulators that all of the other 100-plus wells are safely functioning. SoCal can fill the majority of its demand through interstate pipeline receipts, but it does need to rely on storage during peak demand times of the year.
SoCal demand usually ranges between 2-4 Bcf/d, but can reach as high as 5 Bcf/d on the strongest demand days. The utility could theoretically fill all of its demand on all but a few days a year from longhaul flows to its Wheeler Ridge, North and South Zones, which have capacity of over 3.7 Bcf/d. These interconnects bring gas in to Southern California from the Rockies, Texas and New Mexico.01-28-16 SoCal gas demand
However, these zones never receive enough gas to push near that capacity level, so the rest is filled in with storage withdrawals. Aliso Canyon makes up about half of SoCal’s withdrawal capacity, but the other three fields on SoCal’s system can pull up to 1.8 Bcf/d from storage. This means that if you combine the capacity of the three major zones with this withdrawal capacity, SocalCal’s total capacity to meet demand is nearly 5.6 Bcf/d. Seems like SoCal shouldn’t have any reliability issues with all this capacity, right?

But let’s take a closer look at the utilization of the three major zones. These zones usually receive between 2-3 Bcf/d from long-haul pipes such as El Paso and Transwestern from the desert Southwest, Kern River, and Southern Trails from the Rockies, as well as some from its intrastate neighbor Pacific Gas & Electric to the North. Even though there is a capacity of 3.7 Bcf/d between these zones, there is only 2.6 Bcf/d of contracted firm rights in place to deliver supplies.01-28-16 SoCal gas receipts
When you combine this 2.6 Bcf/d figure with the 1.8 Bcf/d of withdraw capacity without Aliso Canyon, you get to 4.4 Bcf/d. Since demand can reach as high as 5 Bcf/d, there could be some price spikes in order to attract gas to the SoCal Border on high demand days in the winter.
This could be a longer-term issue as well, and there could also be some price spikes next winter if the field isn’t back in operation at that point. SoCal could bring up LNG supplies from the Costa Azul terminal in Baja, California, but prices would have to be pretty high to incentivize LNG dispatch. It’ll be interesting to watch how this shakes out and if SoCal adds incremental contracts from some of those long-haul pipelines.

Source: http://blogs.platts.com/

98 is the number to remember for US gasoline in the 2020s

Gasoline and ethanol are joined at the hip. They’re like lamb and mint. Macklemore and Ryan Lewis. Frodo and Gollum.
And nope, you are not going to get me to say which one is Gollum.
What I will say is that I, as a gasoline editor, do not feel like the enemy here (as some have suggested) at the National Ethanol Conference in New Orleans, where Platts is one of dozens of sponsors and where the big talk this week is how to get octane of gasoline up near 100 at the pump. (You know octane from the little yellow sticker that says “R+M” on it. You probably buy gasoline at 87, 89, 91, 92 or 93 octane.)
Octane helps your engine resist knock, the tiny explosions happening nowhere near where they are supposed to happen in your car. (1) Knock, knock. (2) Who’s there? (3) Engine. (4) Engine who? (5) This isn’t a joke. It really is your engine. Start buying the right gasoline.
Anyway, I’m just here for the octane. Researchers from Ford and the US Department of Energy and a longtime consultant on fuel economy talked Tuesday morning at the Hyatt Regency about the march toward higher-octane gasoline and the cars that will burn them. Also on the table: how much of that gasoline will be comprised of ethanol beyond the 10% seen in most US markets today.

Deep thoughts needed.
“Some deep thought is needed on flex-fuel vehicles and higher octane,” said Dave Hirshfeld of the two-person MathPro Inc. energy consulting shop in Washington, D.C.
Ethanol cares about this because ethanol, at 113 octane, is a great way to get your octane level higher. It’s the double-shot latte of the gasoline blend. But our biofuels analyst — Jordan Godwin, the guy who asked me if I felt like the enemy — said ethanol’s contribution to fuel economy is a bit sketchy. That is for another blog post and points to a broad issue that Godwin told me this morning that not many here in New Orleans are talking about.
The consensus at the panel is that 98 octane is the best target for US gasoline, and Hirshfeld said it would take about eight years to get there if there is political willpower to get it done. The next president no doubt will have something to say.
Gasoline at 98 octane probably would cost 15 cents/gal more than gasoline at 92 octane, researchers said.
Tom Leone, Ford automotive fuels researcher and the most optimistic member of Tuesday’s three-person panel, said he foresees a day when 98 octane gasoline is the US standard, like 87 octane is today for regular gasoline. He said Ford is interested in building cars that use the gasoline of the people, as it were — the most widely available fuel.
“We can deliver a vehicle that runs on any kind of fuel. But we need to know what that fuel will be,” he said.
Beyond 98 octane gasoline lies the “octane frontier,” Hirshfeld said. Those gasolines would require more and more ethanol and likely would not be viable in the market.
Leone said premium gasoline today, the fuel at 91 octane and up, is more of a marketing concept than an economic need. Buying premium gasoline delivers 1% to 2% better fuel economy but that gasoline typically costs 10% more, Leone said. Few are willing to pay that beyond owners of sports cars and luxury sedans.
So what next? Getting the various interests in the octane debate to agree may be as complicated as, say, organizing a nude opera.
Outlandish ideas are likely be proposed. Leone said one rejected technology involved a car where the driver had to fill two tanks with different gasolines. And fuel standards will draw political scrutiny.
“No one likes to be regulated,” Leone said.
But he said there are “societal gains” to be found in higher-octane gasolines, particularly in fuel economy. “It is hard to see market forces alone getting us there,” he said.

Source: http://blogs.platts.com/

The Bakken oil production decline officially begins

For months, analysts have said that reports of the death of the Bakken oil boom have been greatly exaggerated.

Despite the historic collapse in oil prices and North Dakota’s rig count falling to levels not seen since 2009, producers have largely maintained steady supply levels as they employed better technology in the most promising geology.

While production wasn’t nearing 2 million b/d as some statewide officials had dreamed of a year earlier, it was holding stable in a range of about 1.16 million b/d to 1.21 million b/d throughout much of last year and even increased from one month to the next five times throughout the year.

When monthly production did fall off, it was incremental and often blamed on secondary factors, like flaring reduction targets or oil conditioning rules.

But the long-awaited drop in Bakken production may have officially begun, as data released by North Dakota’s Department of Mineral Resources this week shows.

Daily oil production averaged just over 1.15 million b/d in December, down 29,506 b/d, or 2.5%, from the previous month. It marks the lowest daily production level in the state since August 2014 and the first real downturn in statewide oil supply caused by the persistent dip in prices.

“This looks like it’s a real number, based on real activity,” said Lynn Helms, the state’s top oil and gas regulator.

The mantra for North Dakota oil producers has become “lower for longer” as operators brace for oil prices which may make drilling uneconomic in nearly every part of the Bakken play, Helms said.

Helms this week released quarterly breakeven numbers which show that only two North Dakota counties, Dunn and McLean, remain economic to drill amid current prices. Dunn, where the state estimates breakeven prices average $22/b, had seven active rigs Wednesday, while McLean, where breakevens average $25/b, had just one.

McKenzie County, which leads the state with 20 active rigs, has an average breakeven of $31/b. The statewide breakeven average is $40/b. (We considered the question of how low prices can go in the Bakken last summer in an episode of Capitol Crude: The US Oil Policy Podcast.)

While Helms said that while he expects statewide production to remain above 1 million b/d throughout early 2017, maintaining that level will require WTI spot prices to average about $45/b. This is possible, according to US Energy Information Administration projections, which show WTI averaging about $37.59/b this year, but climbing to an average of $50/b next year.

But there’s much uncertainty in those projections, according to Howard Gruenspecht, EIA’s deputy administrator.

The EIA actually forecasts a range of prices, between $20/b to over $100/b by the end of 2017, due to a variety of uncertain factors such as social unrest in oil dependent countries, a dramatic OPEC move, a rise in unplanned outages or Iran exceeding export expectations.

“There’s a lot of reasons that prices could be higher, there’s some reasons prices could be lower,” Gruenspecht said during a Center for Strategic and International Studies event this week.

Still, the EIA’s production forecast echoes those in North Dakota.

The EIA expects US crude production to fall from an average of 9.43 million b/d in 2015 to 8.69 million b/d this year and fall further to an average of 8.46 million b/d in 2017, according to the agency’s most recent Short-Term Energy Outlook.

While the yearly average will be lower next year, the EIA sees production bottoming out in September 2016 at 8.31 million b/d, falling from 9.04 million b/d this month and representing a steep 730,000 b/d drop over seven months.

The forecast shows that the EIA believes that the US oil renaissance clearly peaked in April of 2015 when production averaged 9.69 million b/d, but also that producers may be nearing a steady, long-term supply level.

In North Dakota, where the number of drilling permits continues to fall and the number of inactive wells continues to grow substantially, producers remain pessimistic in the near term.

But there is some more long-term optimism, Helms said, as venture capitalists and hedge funds have begun to buy up Bakken assets. Nearly 700 wells were in the process of being transferred from one operator to another, Helms said.

“They think this is a fantastic purchasing opportunity,” he said.

Helms said only time will tell if that translates into a supply rebound or “lower for longer” for even longer.

Source: http://blogs.platts.com/

Ethanol and the race to higher octane standards in the US: Fuel for Thought

With the US likely to raise the gasoline octane standard in the next decade or so to achieve greenhouse-gas emissions regulations and fuel efficiency targets, the domestic ethanol industry is promoting its product as the most cost-effective and environmentally friendly way to meet those higher requirements.

In fact, that was the main thrust of the Renewable Fuels Association’s National Ethanol Conference in New Orleans last week.

While the conference in recent years has focused primarily on the regulatory uncertainty surrounding the US biofuels blending mandate, this year’s stressed the need to look beyond that statute for growth.

And one way the RFA aims to do that is to highlight ethanol’s octane benefits, given its price and environmental advantages to petroleum-based additives, such as alkylate and reformate.

“The world is octane short, and with a blending octane rating of 113, ethanol offers more engine knock resistance per dollar than any other gasoline additive on the planet,” RFA President Bob Dinneen said in his state of the industry address.

The current standard for most of the US is 87 octane for regular gasoline. The higher the octane, the lower the engine “knock,” or misfiring of the gasoline within the engine, improving efficiency and lowering emissions.

In tandem with raising the octane of gasoline, automakers could redesign their engines to improve their compression ratio to further enhance efficiency.

But significant challenges remain to simply blending more ethanol into the US gasoline pool to raise its octane.

For one, vehicle engines would have to be redesigned to tolerate the more corrosive higher ethanol blends.

While many automakers have begun to warranty their vehicles for E15 — a 15% blend of ethanol with gasoline — experts say blends of E25 or E30 would likely be necessary to meet the higher octane standard.

Ethanol also has a higher Reid Vapor Pressure than some other blendstocks, which makes it more challenging to meet the Environmental Protection Agency’s summer gasoline specifications.

On the other hand, using reformate or alkylate to boost octane would require refineries to invest significantly in their capacity to produce those blendstocks, which are significantly more expensive than gasoline.

Valero, Marathon Petroleum and other US refiners have already announced plans to increase alkylation production to take advantage of strong demand and sizable margins.

Platts has assessed alkylate FOB Houston as high as 38 cents/gal above Gulf Coast conventional pipeline gasoline in recent days, while reformate FOB Houston has been assessed as high as 65 cents above Gulf Coast gasoline.

Chicago Argo ethanol, meanwhile, has traded about 43 cents/gal above CBOB gasoline recently. But the Argo-CBOB spread has been volatile, with ethanol spending most of 2015 at a discount to gasoline.

Tom Leone, a technical expert on powertrain evaluation and analysis with Ford Motor Company, said so far there has been a lack of consensus among automakers, refiners, fuel distributors and government and standards organizations on which pathway to follow.

Bumps in the ethanol road

“The transition will be difficult,” he said. “To get the biggest benefits, the engines need to be optimized to take advantage of the high octane fuel. Whether it’s higher ethanol blends or increasing octane at the refiner level in E10, there are challenges to both approaches. There are investments required on both sides. It’s not an obvious choice for us.”

Count John Eichenberger, executive director of the Fuels Institute, as a skeptic that higher ethanol blends can be the solution to raising octane.

“30% ethanol will be a problem,” he said. “If [the new fuel] is restricted to new vehicles, there’s not going to be sufficient demand for retailers to put it in. The question is, what is that threshold?”

Whatever the solution to the higher octane problem, it will almost certainly be a lengthy transition process. The switchover from leaded to unleaded gasoline took 12 years before leaded gasoline was fully phased out in the US.

The RFA is hoping to get an early edge on the process.

Dinneen noted that Europe has a standard of 95 research octane number, or RON, which is a different calculation than the US uses but is nonetheless higher than the US’ standard.

He said the RFA would push US regulators to adopt that European standard. Once the new regulation is adopted, ethanol would have to compete in the marketplace.

“A higher octane fuel would enable the auto industry to increase engine compression to improve fuel economy and performance,” Dinneen said. “In a competitive octane environment, everybody wins.”

–Herman Wang in Washington

Source: http://blogs.platts.com/